Method for well testing

ABSTRACT

The present document discloses techniques to perform an impulse well test for formation property estimation of subsurface reservoirs. It disclosures a method to obtain the optimum time range of a downhole isolation valve closure to achieve an acceptable depth of investigation for an impulse test and methodologies to optimize the execution of an impulse test using the simulated and measured real time bottomhole pressure data. It is emphasized that this abstract is provided to comply with the rules requiring an abstract which will allow a searcher or other reader to quickly ascertain the subject matter of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

FIELD OF DISCLOSURE

The present application is generally related to the testing of a subsurface formation, and more particularly to a method for testing a subsurface formation using a technique known as well test. Novel methodologies and systems to achieve the measurement of formation properties and environmental data will also be discussed in the present disclosure by ways of several examples that are meant to illustrate the central idea and not to restrict in any way the disclosure.

BACKGROUND OF DISCLOSURE

Wellbores are drilled to locate and produce hydrocarbons. A downhole drilling tool with a bit at the lower end thereof is advanced into the ground to form a wellbore. As the drilling tool is advanced, a drilling mud is pumped from a surface mud pit, through the drilling tool and out through the drill bit to cool the drilling tool and carry away cuttings. The fluid exits the drill bit and flows back up to the surface for recirculation through the tool. The drilling mud is also used to form a mudcake to line the wellbore. The wellbore in its entirety or partially may or may not be cased after it is drilled. During the life of a well it is desirable to conduct measurements to the producing subsurface reservoir formation to assess its commercial potential. The tests used to evaluate the reservoir are varied and widely understood in the industry. Different tests may measure different characteristics of the reservoir and its effluents but the intent of all the tests are focused to understanding the basic questions needed to successfully manage a producing well; some of such questions are: how much hydrocarbon is in the reservoir? How much hydrocarbon can be produced and by what means? What are the dimensions of the reservoir? The answer of these questions, or rather the pieces of a puzzle that will help answer the questions, usually comes from measuring the formation and effluent properties such as porosity, permeability, skin, damage, viscosity, density, pressure, temperature, etc. Most of these measurements can be obtained by performing what is commonly known in the industry as a well test.

In some cases the reservoir characteristics are well understood but the performance of a particular well that is producing hydrocarbons to surface is not as expected, and then the well is often tested to determine the direct causation of this lack of flow rate. This is normally characterized by a dimensionless factor called skin, which quantifies the production efficiency of a formation. The wellbore damage or flow restriction must then be assessed to determine an appropriate method to treat the damage effectively. This damage can be the result of many conditions such as but not limited to solid or mud-filtrate invasion, perforating debris, inadequate perforations, near or far wellbore damage and low permeability formations. To properly treat a damaged well, we first need to understand the origin and nature of the damage. One way to achieve this is by analyzing well test data.

One of the preferred methods used in well test interpretation is pressure transient analysis (also called “PTA”). This method combines flow rate and bottomhole pressure measurements obtained by flowing the well through instruments at the surface and by recording the bottomhole pressure with the well shut-in. Both measurements (flowing and shut-in) are recorded at one or a plurality of time periods depending on the complexity of the study. The pressure and pressure derivative curves are compared to known type-curves to determine the skin and permeability. After the treatment is formulated and executed, a post stimulation test may be conducted to record a final skin.

Well test is a primary technique to obtain the formation and fluid properties in a subsurface reservoir. In a typical well test, bottom-hole pressure (BHP) is recorded during pressure drawdown and buildup, and representative reservoir fluid samples are captured. The BHP history can be used to infer formation permeability or productivity, damaged skin factor and initial reservoir pressure. The reservoir fluid samples are used in laboratory to measure the fluid properties, such as viscosity, compressibility, gas-oil-ratio, formation volume factor etc. Various tools have been used in order to conduct a well test.

Traditionally, Drill Stem Test (DST) has been widely utilized in the formation evaluation. A DST is usually carried out after a well is drilled but before a permanent completion is installed. In general, a conventional DST tool string consists of various bottom-hole flow control valves, production packer, and pressure gauges. A conventional DST requires producing formation fluids to surface through the pipe string that conveyed the tools. Its operation includes one or several short flowing and shut-in cycles for cleanup before a main flowing and shut-in test. The short flowing and shut-in periods in a conventional DST usually last about tens of minutes to several hours. The main flowing and shut-in periods often last about tens of hours to several days or even longer. The time scale of the flowing and buildup periods in a conventional DST is about 10³ to 10⁶ or more seconds. The produced formation fluid volume is about 10³ barrel to 10⁵ or more barrels. The large amount of produced formation fluid generates a large and deep pressure disturbance in the formation. Therefore, a conventional DST provides robust estimates of the formation parameters with a large depth of investigation. However, because a conventional DST involves a drilling rig, long testing times, and large amount of produced hydrocarbon or fluids from formation, it requires a significant investment and considerable time for preparation and execution. There are also many associated environmental and safety risks in a conventional DST. Another challenge associated with a conventional DST is that it needs to properly handle a large amount of produced hydrocarbon, which is a safety hazard and usually requires special and heavy equipment on surface to deal with the produced fluids. This substantially increases the test cost, particularly in logistically difficult places.

To circumvent the conventional DST difficulties and reduce operational cost, a variant of the conventional DST is often conducted. This type of test is commonly known in the industry as impulse test, surge test or perforating inflow diagnostic test. The basic principles of the impulse test are reflected in U.S. Pat. No. 4,677,849 issued Jul. 7, 1987 entitled “Hydrocarbon Well Test Method” to Joseph Ayoub et al and assigned to Schlumberger Technology Corporation. The surge or impulse test will be used interchangeably in the present disclosure. In this type of test, a chamber (also called surge chamber) is formed by limited length of inner void volume in pipe strings (drill pipes, tubing pipes or coiled tubing pipe). A ball valve or isolation device is set on the bottom end of the chamber. The upper end of the chamber can be either open to surface production facility or closed by another isolation valve. In the latter situation, the test is also called closed chamber test. To produce the formation fluid and initiate a test, the chamber above the lower isolation valve is charged with a low pressure air or other gases, for example, nitrogen etc. The low pressure in the air chamber is maintained by closing the isolation valve at the lower end of the chamber during running in the hole. When the lower isolation valve is open, the high formation pressure pushes formation fluid into the chamber filled with lower pressured air or gas. For liquid reservoirs, the produced liquid formation fluid will gradually occupy more chamber volume. Generally, filling the chamber with formation fluid is terminated when the bottomhole wellbore pressure reaches the equilibrium with the formation pressure or certain amount of formation fluid is produced in the chamber. Because limited or even no hydrocarbon flows to surface, an impulse test requires much simpler surface equipment. This can be a significant advantage in remote locations and harsh environment because of less logistic expenses. Constricted primarily by the volume of the chamber, the amount of formation fluid produced in an impulse test is in the order of 10⁰ to 10² barrels. The test time lasts 10² to 10⁴ seconds depending on the reservoir and chamber conditions. Because an impulse test produces much less formation fluid than a conventional DST, it generates smaller pressure disturbance in the formation and, thus, a smaller depth of investigation.

The use of coiled tubing as a mean to well test a particular formation is not new to the industry. Such operations are disclosed in several U.S. patents mentioned hereinafter: U.S. Pat. No. 5,287,741 entitled “Methods of Perforating and Testing Wells Using Coiled Tubing”, issued Feb. 22, 1994 to Schultz et al; U.S. Pat. No. 5,638,904 entitled “Safeguarded Method and Apparatus for Fluid Communication Using Coiled Tubing, With Application to Drill Stem Testing”, issued Jun. 17, 1997 to Misselbrook and Sask; U.S. Pat. No. 6,520,255 entitled “Method and apparatus for stimulation of multiple formation intervals”, issued on Feb. 18, 2003 to Randy C. Tolman et al; U.S. Pat. No. 6,959,763 entitled “Method and apparatus for integrated horizontal selective testing of wells”, issued on Nov. 1, 2005 to Hook and Ramsey; U.S. Pat. No. 6,675,892 entitled “Well Testing Using Multiple Pressure Measurements” issued on Jun. 13, 2004 to Fikri Kuchuk, et al.; and U.S. Patent Application Publication No. 20070044960 entitled “Methods, systems and apparatus for coiled tubing testing” published on Mar. 1, 2007 on behalf of John Lovell et al.

Other related literature in the field of disclosure are: U.S. Pat. No. 7,086,463 issued Aug. 8, 2006 titled “Methods of downhole testing subterranean formations and associated apparatus therefor” to Paul David Ringgenberg et al; U.S. Pat. No. 6,729,398 issued May 4, 2004 titled “Methods of downhole testing subterranean formations and associated apparatus therefor” to Paul David Ringgenberg et al; U.S. Pat. No. 6,622,554 issued Sep. 23, 2003 titled “Open hole formation testing” to Kevin R. Manke et al; U.S. Pat. No. 6,527,052 issued Mar. 4, 2003 titled “Methods of downhole testing subterranean formations and associated apparatus therefor” to Paul David Ringgenberg et al.

Because formation fluid usually enters the chamber at high speed at the beginning of a surge flow, the pressure signal obtained in an impulse test can be quite noisy. This affects the accuracy of formation parameter estimation. One way to resolve the noisy data is to implement a downhole shut-in at the isolation valve. After the isolation valve is closed, the pressure data after the valve closure can have high quality similar to a pressure buildup test in a conventional DST. However, the timing of the isolation valve closure is critical. If closing too early, the produced formation fluid volume will be very small, leading to a small pressure disturbance in the formation and a shallow depth of investigation. On the other hand, if closing too late, the bottomhole pressure will approach to the equilibrium and the formation pressure disturbance decreases, also resulting in a small depth of investigation. For a closed chamber test, a novel technique has been disclosed in U.S. Pat. No. 7,478,555 dated January 20^(th) 2009 entitled “Technique and Apparatus for use in well testing” issued to Lang Zhan et al and assigned to Schlumberger Technology Corporation, the above mentioned patent which is herein incorporated by reference describes a way to optimize the test by closing the bottomhole isolation valve at the optimal shut-in time. The techniques disclosed in the present application will address an impulse test in which the upper end of the chamber may or may not be closed and wherein even if the upper end of the chamber is closed it will have a negligible effect on the bottomhole pressure interpretation.

It is an object of the present application to provide an improved method for characterizing a well subsurface formation that avoids one or more of the problems with known methods.

SUMMARY OF THE DISCLOSURE

The following embodiments provide examples and do not restrict the breath of the disclosure and will generally describe a method for well testing, comprising communicating fluid from the well into a chamber in connection with a well test; determining the optimal time to close an isolation valve connected to the chamber and isolating the chamber from the well.

Preferably, the optimal time to close the isolation valve is determined by using the liquid fluid length and total produced volume in the chamber. In a second preferred embodiment the optimal time is determined by obtaining the maximum valid test time after the isolation valve closure.

In a third preferred embodiment the optimal time to close the isolation valve is determined by obtaining the maximum depth of investigation after the isolation valve closure.

It is also proposed a method to design an impulse well test comprising providing a chamber for communicating with a fluid from the well wherein the chamber comprises an isolation valve and selecting a range of isolation valve closure times as a function of a targeted depth of investigation value within the underground formation surrounding the well. In a preferred embodiment, the targeted depth of investigation is determined using a measured real-time bottom hole pressure data.

Further features and advantages of the disclosure will become more readily apparent from the detailed description when taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a tool string for well perforating and impulse testing.

FIG. 2 shows a tool string for an impulse test.

FIG. 3 shows a chart of bottom hole pressure and flow rate histories for an impulse test.

FIG. 4 shows a chart of produced fluid length and total produced volume in the surge chamber for the impulse test.

FIG. 5 shows a chart of the simulated valid test time and depth of investigation for the impulse test.

FIG. 6 shows a workflow to optimize executions of an impulse test to achieve maximum acceptable depth of investigation using real time bottomhole pressure measurements.

DETAILED DESCRIPTION OF THE DRAWINGS

The following description provides exemplary embodiments only, and is not intended to limit the scope, applicability, or configuration of the disclosure. Rather, the following description of the exemplary embodiments will provide those skilled in the art with an enabling description for implementing one or more exemplary embodiments. It being understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the invention as set forth in the appended claims.

Specific details are given in the following description to provide a thorough understanding of the embodiments. However, it will be understood by one of ordinary skill in the art that the embodiments may be practiced without these specific details. For example, systems, processes, and other elements in the invention may be shown as components in block diagram form in order not to obscure the embodiments in unnecessary detail. In other instances, well-known processes, structures, and techniques may be shown without unnecessary detail in order to avoid obscuring the embodiments. Further, like reference numbers and designations in the various drawings indicate like elements.

Also, it is noted that individual embodiments may be described as a process which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations can be performed in parallel or concurrently. In addition, the order of the operations may be re-arranged. A process may be terminated when its operations are completed, but could have additional steps not discussed or included in a figure. Furthermore, not all operations in any particularly described process may occur in all embodiments. A process may correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination corresponds to a return of the function to the calling function or the main function.

Furthermore, embodiments of the invention may be implemented, at least in part, either manually or automatically. Manual or automatic implementations may be executed, or at least assisted, through the use of machines, hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof. When implemented in software, firmware, middleware or microcode, the program code or code segments to perform the necessary tasks may be stored in a machine readable medium. A processor(s) may perform the necessary tasks.

In the following detailed description of the preferred embodiments, reference is made to accompanying drawings, which form a part hereof, and within which are shown by way of illustration specific embodiments by which the invention may be practiced.

FIG. 1 shows a typical tool system used for a perforating and impulse testing job. The tool string 10 is run into well and suspended in the wellbore 11 with the perforating gun 13 opposite the intended zone of a subterranean formation. A safety spacer 15 and a firing head 17 are installed above the perforating gun to detonate the charges. After a section of tubing 19, a debris sub 21 and a slotted tail pipe 23 are used to allow communication between wellbore 11 and inner bore of the upper tool string. Further above is the packer 25, which can be set to isolate the lower wellbore 11 from upper wellbore 31. Safety joint 37 and hydraulic jar 40 are usually installed above the packer to provide a quick release of the upper tool string and upward pulling shocks, respectively, in case of the tool stuck. Gauge carrier 42 usually is installed above the hydraulic jar 40 and below the major test valve 44. A typical gauge carrier 42 can hold several gauges that may be ported to the inner bore of the tool string 10 to record pressure-temperature measurements during the operation. The test valve 44 is usually a ball or flapper type valve, which allows opening or closing the flow passageway of the tool string 10. After the packer 25 is set, the perforating gun 13 can be fired to establish communication between formation and wellbore 11. Then, opening the test valve 44 allows the formation fluid flowing from the perforated zone into the surge chamber formed by the pipe string 48 or injecting working fluid from surface to formation through the wellbore 11 below the packer 25. When closing the test valve 44, the fluid in the wellbore 11 below the packer 25 is isolated from the tool string above the test valve 44. The pressure measurement at gauge 42 below the test valve 44 will not be affected by the flow dynamic transport above the closed test valve. Therefore, the quality of pressure measurement has high quality similar to a conventional pressure buildup well test. The circulating valve 46 permits or prevents fluid flow between the inner bore of the upper pipe string and the wellbore 31 above the packer 25. When the test valve 44 is closed, opening the circulating valve 46 enables to lift the produced formation fluid in the pipe string above the test valve 44 up to the surface by injecting working fluid in the wellbore annulus 31.

Note that the devices described in FIG. 1 are given just for an illustration purpose for a typical perforating and well test operation. As known from the skilled person in the art, some of the depicted devices can be absent or duplicated without affecting the operations. Furthermore, other devices may be installed to add or replace the components that are given in FIG. 1. For example, the perforating gun 13, safety spacer 15 and firing head 17, blank tubing 19 or debris sub 23 may not be required if perforating is not needed to open communication between the tested formation and wellbore 11. Alternatively, another packer or a plug can be installed at the bottom of the string to isolate the production zone; a straddle packer system may also be used if required.

FIG. 2 shows another tool system 60 that is used for an impulse test. Because perforating is not an objective, the entrance of the inner bore 62 is installed at the end of the system 60. An isolation packer 64 and emergency shear release sub 66 are connected above the entrance 62. After unloader sub 68 and a crossover, an isolation valve 70 is installed. This valve is closed when running in the wellbore to isolate the low pressure chamber formed by the working pipe 78 from the high pressure environment below the valve and in the wellbore. The working pipe 78 can be drill pipe, tubing, coiled tubing or any tubular conveyance. 72 is the pressure gauge that is used to record the pressure transient during the test. 74 is another isolation valve that is open during the running in hole. 76 is a circulating valve to allow communication between the inner and outer of the tool string.

When running in hole, the isolation valve 70 is closed to maintain a low pressure in the air chamber above it. After positioned at the targeted location, the packer 70 is set to isolate the wellbore below the packer and the annulus above the packer. The impulse test is initiated when the isolation valve 70 is open. This allows formation fluid with a higher pressure entering the surge chamber with a low pressure. After certain amount of formation fluid is produced and before the bottomhole pressure reaches the formation pressure, the second isolation valve 74 is closed to isolate the surge chamber from the wellbore fluid below the valve 74. Because of this isolation, the pressure measurement at the gauge 72 below the closed valve 74 will not be affected by the flow transport in the surge chamber. This enables the pressure measurement after the closure of the valve 74 to have high quality. The test is terminated after the sufficient measurement time is completed.

Note that the testing system 60 is an exemplary tool string that can be used for the purpose of an impulse test. Some devices in the tool string can be replaced by other devices with similar functionality. For example, the two isolation valves 70 and 74 can be replaced by one isolation valve located above the pressure gauge 72 with both opening and closing capability. Means for transfer data to and from surface to the downhole tool string may be used, such means to transfer data may include wire, wireless, optical, mud pulses or sound waves among other means known to a person skilled in the art and widely used in the industry. Through this communication line, the pressure, temperature and other bottom hole measurements can be transmitted to surface. Human operators on surface are able to execute the operations accordingly based on these real time measurements sending to the surface.

As stated above, the testing systems 10 and 60 require closing the isolation valves 44 and 74, respectively, in order to prevent the violent flow dynamics in surge chamber from affecting the bottomhole pressure measurement. The high quality bottomhole pressure data is necessary for reliable formation property estimation. Determining the appropriate closing time for the isolation valve 44 and 74 in system 10 and 60 is very important. If closed too early, produced formation fluid volume is too small so that the depth of investigation will be small. If closed too late, the bottomhole pressure will approach the formation pressure, leading to small pressure change after the test valve closure. This also renders a small depth of investigation using the pressure data after the closure of the isolation valve. Therefore, there exists an optimum time for the isolation valve closure so that an impulse test will provide the maximum depth of investigation. U.S. Pat. No. 7,478,555 dated January 20^(th) 2009 entitled “Technique and Apparatus for use in well testing” issued to Lang Zhan et al and assigned to Schlumberger Technology Corporation, disclosed a method to identify this optimum test valve closure time for specific testing conditions. If the surge chamber volume is relatively small and the upper end is closed, the bottomhole and chamber pressure will show unique characteristics (pressure hump, spikes in pressure derivatives etc) at the time that the surge chamber is nearly filled. U.S. Pat. No. 7,478,555 uses these unique characteristics in the pressure histories to determine the optimum time for the closure of the isolation valve. However, in many practical cases, the surge chamber can be very large. For example, if the tool string is conveyed using coiled tubing, there will have a large empty volume on the surface reel. Furthermore, if the reservoir has relatively weak pressure, the produced fluid in the surge chamber will not rise very high in the chamber to significantly compress the chamber air. Consequently, the unique characteristics of the bottomhole and chamber pressures could be very weak. Application of the techniques disclosed in U.S. Pat. No. 7,478,555, to this case may not be possible. In other situations, the upper end of the surge chamber may not be closed and is directly connected to production facility. The characteristics of bottomhole and surge chamber pressures may not occur because the air pressure above the produced liquid formation fluid does not change appreciably and has negligible effect on the bottom-hole pressure. The following embodiment of this invention is to determine the optimum closing time of the isolation valve 44 or 74 for the testing systems that do not have the strong characteristics of the bottomhole and chamber pressures.

The impulse test conducted using the testing system 10 or 60 can be simulated by a numerical simulator. This numerical simulator integrates flow transports in reservoir and wellbore with consideration of variable skin factor. The flow dynamics in reservoir is governed by the pressure diffusivity equation with the following initial and boundary conditions:

$\begin{matrix} {{\frac{1}{r}\frac{\partial}{\partial r}\left( {r\frac{\partial p}{\partial r}} \right)} = {\frac{{\mu\varphi}\; c_{t}}{k}{\frac{\partial p}{\partial t}.}}} & \left( {{Equation}\mspace{14mu} 1} \right) \\ {{p\left( {{t - 0},r} \right)} = p_{i}} & \left( {{Equation}\mspace{14mu} 2} \right) \\ {{p_{w}(t)} = \left\lbrack {{p(t)} - {{s(t)}\left( {r\frac{\partial p}{\partial r}} \right)}} \right\rbrack_{r = r_{w}}} & \left( {{Equation}\mspace{14mu} 3} \right) \end{matrix}$

The bottomhole pressure p_(w)(t) and skin variation S(t) are unknown in the above formulae. The former is determined from the coupled reservoir-wellbore flow model while the latter is simulated by the following skin variation model:

$\begin{matrix} {{S(t)} = \left\{ \begin{matrix} {{\frac{\left( {S_{I} - S_{E}} \right)}{\left\lbrack {1 - {\exp \left( {- \lambda} \right)}} \right\rbrack}\left\lbrack {{\exp \left( {- \frac{\lambda \; t}{t_{s}}} \right)} - {\exp \left( {- \lambda} \right)}} \right\rbrack} + S_{E}} & {t \leq t_{s}} \\ S_{E} & {t > t_{s}} \end{matrix} \right.} & \left( {{Equation}\mspace{14mu} 4} \right) \end{matrix}$

where λ is a constant, S_(I) and S_(E) are the initial and ending skins during the surge period within a characteristic interval of time, t_(s), during which the skin substantially varies. The wellbore fluid hydraulics can be described by one dimensional pipe flow equations. All the parameters involved in the model (pressure p, density ρ, and velocity v) are averaged over the actual cross-sectional area of the wellbore A(z). If heat exchange and temperature effects are neglected, the wellbore flow is governed by the following equations:

$\begin{matrix} {{{\frac{\partial}{\partial t}({Ap})} + {\frac{\partial}{\partial z}\left( {A\; \rho \; v} \right)}} = Q} & \left( {{Equation}\mspace{14mu} 5} \right) \\ {{{\frac{\partial}{\partial t}\left( {A\; \rho \; v} \right)} + {\frac{\partial}{\partial z}\left( {A\; \rho \; v} \right)}} = {{{- A}\frac{\partial p}{\partial z}} - F - {A\; \rho \; g}}} & \left( {{Equation}\mspace{14mu} 6} \right) \\ {\rho = {\rho (p)}} & \left( {{Equation}\mspace{14mu} 7} \right) \end{matrix}$

The source term Q in Equation 5 is the flow rate from formation and F in Equation 6 is the frictional force acting on the fluid in the pipe. The wellbore flow equations connect to that of the reservoir through Q:

$\begin{matrix} {Q = {{- \frac{2\pi \; k}{\mu}}\left( {r\frac{\partial p}{\partial r}} \right)_{r = r_{w}}}} & \left( {{Equation}\mspace{14mu} 8} \right) \end{matrix}$

The friction force F is estimated using the fluid velocity v in the pipe and the friction factor f. For laminar flow with Reynolds number Re<2000, the friction factor is expressed as:

f=64/Re  (Equation 9)

where the Reynolds number is defined as

$\begin{matrix} {{Re} = \frac{\rho \; {vd}}{\mu}} & \left( {{Equation}\mspace{14mu} 10} \right) \end{matrix}$

For turbulent flow with Reynolds number larger than 2000, the friction factor is estimated using the Colebrook-White correlation

$\begin{matrix} {\frac{1}{\sqrt{f}} = {{- 2}{\log\left( {\frac{\delta}{3.7d} + \frac{2.5}{{Re}\sqrt{f}}} \right)}}} & \left( {{Equation}\mspace{14mu} 11} \right) \end{matrix}$

Equation 5 and Equation 6 are the mass and momentum balance equations for flow inside wellbore. Equation 7 is the equation of state (EOS) for the fluid inside wellbore. Assuming single phase flow in formation and applying a lump sum wellbore dynamic model, the flow equations Equation 5-Equation 7 can be simplified and then solved simultaneously with the reservoir Equation 1.

The bottomhole pressure and flow rate histories for an impulse test can be simulated using the numerical simulator. The results of the impulse test without the test valve closure are shown in FIG. 3. In this case, the reservoir pressure is 4000 psi, the formation thickness is 32.8 ft, the wellbore diameter is 0.82 ft, tubing diameter is 5.1 in., dimensionless tubing friction factor is 0.0003, formation fluid API is 30, formation fluid viscosity is 1 cp, formation fluid compressibility is 0.00001 l/psi, formation porosity is 0.2, formation permeability is 100 and skin factor is a constant of 1. In this example, the chamber is assumed to be open to the surface. Therefore, the air pressure above the liquid fluid in the surge chamber does not have effect on the bottomhole pressure.

It can be seen that the flow rate decreases from a large value at the beginning of the test to a very small value. Although continuously increasing, the incremental increase of the bottom hole pressure at large time is very small. Because data analysis of a well test depends on the pressure changes respect to time rather than pressure magnitudes, the very small pressure changes at large test time are prone to be corrupted by noisy flow dynamics in the chamber. As stated previously, the test valve should be closed to isolate the flow dynamics in the chamber from affecting the bottomhole pressure measurements after sufficient formation fluid is produced. Because there is no specific characteristic in the bottomhole pressure and flow rate histories, it is difficult to determine at what time the isolation valve 44 or 74 should be closed if the decision is solely based on the bottomhole pressure and flow rate.

FIG. 4 shows the produced fluid length in the surge chamber and total produced volume during the impulse test. Clearly, the produced fluid length and total produced volume approaches the maximum after about 5000 sec in the test. Thus, the flowing time of 5000 sec is the possible optimum time for the isolation valve closure because further production will almost not increase the total produced formation fluid, hence, will not increase the disturbance of reservoir for better noise and signal ratio.

One drawback of the previous criteria to determine the isolation valve closure time using the produced liquid length and total produced volume is that the changes of the liquid length and total produced volume from fast increase to flat are too gradual after 1000 sec to have a definite time value. The isolation valve closing time determined from these two curves is not very precise because any time between 1000 and 10000 sec seems to be a possible time for the operation. Furthermore, the decision does not really consider the depth of investigation, which gives a more quantitative measure to evaluate the quality of an impulse test.

The depth of investigation for an impulse test can be obtained by modifying the formula given by S. Daungkaew, F. Hollaender and A. C. Gringarten (SPE paper 63077 was presented at 2001 SPE Annual Technical Conference and Exhibition). According to the paper, the valid test time after the closure of a downhole test valve for a conventional DST can be estimated by:

$\begin{matrix} {{\Delta \; t} = {t_{p}\frac{{\exp \left( {{2L} - \frac{A_{noise}{kh}}{3.53*\mu \; {Bq}}} \right)} - 1}{{\exp (L)} - {{\exp \left( {- L} \right)}{\exp \left( {{2L} - \frac{A_{noise}{kh}}{3.53*\mu \; B}} \right)}}}}} & \left( {{Equation}\mspace{14mu} 12} \right) \end{matrix}$

Where q is the flow rate before the pressure buildup, A_(noise) is the testing noise level, k is the permeability, h is the formation thickness, μ is the viscosity, B is the formation volume factor and L is the logarithmic cycle used for pressure derivative calculation. The Eq. 12 can be modified to accommodate an impulse test as follows:

$\begin{matrix} {{\Delta \; t} = {t_{p}\frac{{\exp \left( {{2L} - \frac{A_{noise}{kht}_{p}}{3.53*24\mu \; {BV}_{p}}} \right)} - 1}{{\exp (L)} - {\quad{\quad{{\exp \left( {- L} \right)}{\exp \left( {{2L} - \frac{A_{noise}{kht}_{p}}{3.53*24\mu \; {BV}_{p}}} \right)}}}}}}} & \left( {{Equation}\mspace{14mu} 13} \right) \end{matrix}$

Where t_(p) is the producing time and V_(p) is the total produced volume. If A_(noise)=0.1 psi, B=1 RB/STB, L=0.1 log cycle, and substituting the total produced formation fluid volume in FIG. 4 into Equation 13, the valid test time after the closure of the isolation valve 44 or 74 can be simulated. The dash line in FIG. 5 shows the calculated valid test time after the closing of the isolation valve for the impulse test. Clearly, the valid test time after the closure of the test valve is very small if the isolation valve is closed at the early time of the test. It gradually increases from the small values at the beginning of the test to the maximum of 40800 sec at the producing time of 5830 sec. After this time, the valid test time decreases dramatically. This means that, for this particular example, the optimum flowing time of the impulse test is 5830 sec. If the well production is terminated by the isolation valve closure at the time of 5830 sec, the valid test time of the pressure measurement larger than the assumed noise level and useful for formation feature identification is the longest of 40800 sec. If the isolation is closed either earlier or later than the optimal time, the valid test time after the valve closure will be shorter. Farther away from the optimal time the valve is closed, the shorter the valid test time will be.

The longest valid test time obtained above gives the largest depth of the investigation using the data after the closure of the isolation valve. The depth of investigation can be obtained by the widely used formula in conjunction with the valid test time:

$\begin{matrix} {d_{inv} = {0.03\sqrt{\frac{k\; \Delta \; t}{\varphi \; \mu \; c_{t}}}}} & \left( {{Equation}\mspace{14mu} 14} \right) \end{matrix}$

The valid test time Δt in Eq. 14 is obtained from Equation 13. The solid line in FIG. 5 gives the estimated depth of investigation for this impulse test. Same as the valid test time, the depth of investigation curve shows a convex shape, which gives the maximum value at the same well flowing time that renders the maximum valid test time. Specifically, the largest depth of investigation of 714 ft occurs at the isolation valve closure time of 5830 sec when the longest valid test time of 40800 sec appears.

Because an impulse test usually produces much smaller amount of formation fluid than a conventional DST, it generally gives a much smaller depth of investigation. On the other hand, one of the major requirements for a well test is to achieve a specific minimum depth of investigation otherwise the estimated formation properties would not be representative. The techniques disclosed above can be used to optimize an impulse test for achieving the maximum depth of investigation. Because the formation properties, such as permeability and skin factor, are not known before an impulse, their values are assumed to be within a particular range based on available geology, geophysics, drilling, logging and other information. The lowest and highest values of permeability and skin factor can be used to calculate the valid test time and depth of investigation curves shown in FIG. 5. Then, the appropriate time for the isolation valve closure can be obtained by selecting the value that satisfies the minimum depth of investigation requirements for all possible variations of the permeability and skin factor. For example, if the minimum depth of investigation is 600 ft for the impulse test shown in FIGS. 3-5, the time range for the isolation valve closure can be from 1530 sec to 20400 sec. For different permeability and skin factor values, this time range will vary. The proper time range of the isolation valve closure is the common time duration that the minimum depth of investigation can be achieved by all simulated permeability and skin factor values. If the time range for the test valve closure does not exist to allow all permeability and skin factor values to achieve the minimum depth of investigation, the test risk can be quantified, i.e., the worst depth of investigation can be estimated based on the simulated results. All these techniques make the impulse test design much more reliable and predictable.

In another embodiment of this invention, an impulse test is optimized using real time bottomhole pressure measurements during its execution. FIG. 6 shows the workflow that is used to optimize an impulse test to achieve the maximum depth of investigation. In Step 1, the formation, fluid and well parameters that are already known are inputted into the numerical simulator. In Step 2, the initial guesses of the unknown formation properties (usually permeability, skin factor and initial reservoir pressure), which will be estimated using the impulse test, are selected and then inputted in the simulator. In Step 3, the bottomhole pressure and flow rate histories of the impulse test are simulated using the inputted properties in Step 1 and Step 2. In Step 4, the bottomhole pressure history measured in real time for the test is loaded into the workflow. In Step 5, the simulated bottomhole pressure history is compared with the measured one. If the difference of these two pressure histories is beyond the acceptable criteria, the unknown formation properties are updated and the workflow goes back to the Step 3 to recalculate the bottomhole pressure and flow rate. If the difference between the two pressure histories is within the acceptable criteria, the workflow advances to Step 5, in which the valid test time and depth of investigation corresponding to each isolation valve closure time are simulated using the simulated flow rate histories by Equation 13 and Equation 14. In Step 6, the depth of investigation corresponding to each possible test valve closure time is obtained and then decision is made based on whether the time to close the isolation valve for the maximum depth of investigation has been reached. If the time to close the isolation valve for the maximum depth of investigation has not been reached, further consideration is whether there is a need to improve the numerical simulation results. If no, the test will continue until the time to close the isolation valve is reached. If yes, the workflow proceeds to Step 3 by updating the unknown formation properties and recalculating the bottomhole pressure and flow rate histories. If the time to close the isolation valve for the maximum depth of investigation has arrived, the operation moves to the final procedure. In the final Step 7, closure of the isolation valve is implemented and the bottom hole pressure is continuously measured for the duration equal to the valid test time before the entire test is terminated. Note that because the valid test time after the isolation valve closure is obtained, the pressure measurements longer than the valid test time will fall below the gauge resolution or the noise will have larger magnitude to mask the true reservoir responses. Therefore, the test conducted longer than the valid test time does not provide any more useful data for data analysis. The technology disclosed here can be used to avoid this non-performing test time so that the unnecessary test cost can be reduced. Similarly, the technique also avoids the test time from being too short such that the longer test after the test valve closure can provide more useful data and larger depth of investigation. All these techniques make the impulse optimized without wasting test time.

An alternative to the workflow shown in FIG. 6 is that the decision of the isolation valve closure can be made if the well flowing time is long enough to give sufficient depth of investigation. The well sometimes has to flow very long time to enable realization of the maximum depth of investigation. However, the well operational condition does not allow such a long time production. In this case, the maximum depth of investigation should not be the primary objective of the test. Although the maximum depth of investigation has not been reached, the well may already flow enough quantify of formation fluid to provide an acceptable depth of investigation after the closure of the isolation valve or other test consideration requires stopping the well flowing. Therefore, decision of the isolation valve closure in Step 6 can still be made to terminate the well production even without achieving the maximum depth of investigation.

The particulars shown herein are by way of example and for purposes of illustrative discussion of the embodiments of the present invention only and are presented in the cause of providing what is believed to be the most useful and readily understood description of the principles and conceptual aspects of the present invention. In this regard, no attempt is made to show structural details of the present invention in more detail than is necessary for the fundamental understanding of the present disclosures, the description taken with the drawings making apparent to those skilled in the art how the several forms of the present invention may be embodied in practice. Further, like reference numbers and designations in the various drawings indicated like elements.

While the invention is described through the above exemplary embodiments, it will be understood by those of ordinary skill in the art that modification to and variation of the illustrated embodiments may be made without departing from the inventive concepts herein disclosed. Accordingly, the invention should not be viewed as limited except by the scope of the appended claims. 

1. A method for well testing, comprising communicating fluid from the well into a chamber in connection with a well test; determining the optimal time to close an isolation valve connected to the chamber and isolating the chamber from the well.
 2. Method according to claim 1, wherein the optimal time to close the isolation valve is determined by using the liquid fluid length and total produced volume in the chamber.
 3. Method according to claim 1, wherein the optimal time to close the isolation valve is determined by obtaining the maximum valid test time after the isolation valve closure.
 4. A Method according to claim 3, wherein the valid test time after the closure of the isolation valve is given by: ${\Delta \; t} = {t_{p}\frac{{\exp \left( {{2L} - \frac{A_{noise}{kht}_{p}}{3.53*24\mu \; {BV}_{p}}} \right)} - 1}{{\exp (L)} - {\quad{\quad{{\exp \left( {- L} \right)}{\exp \left( {{2L} - \frac{A_{noise}{kht}_{p}}{3.53*24\mu \; {BV}_{p}}} \right)}}}}}}$ Where q is the flow rate before the pressure buildup, A_(noise) is the testing noise level, k is the permeability, h is the formation thickness, μ is the viscosity, B is the formation volume factor and L is the logarithmic cycle used for pressure derivative calculation, t_(p) is the producing time and V_(p) is the total produced volume.
 5. Method according to claim 1, wherein the optimal time to close the isolation valve is determined by obtaining the maximum depth of investigation after the isolation valve closure.
 6. Method according to claim 1, wherein the optimal time to close the isolation valve is determined by selecting the time that satisfies the minimum depth of investigation requirements for all possible variations of the permeability and skin factor for the underground formation surrounding the well.
 7. A method to design an impulse well test comprising providing a chamber for communicating with a fluid from the well wherein the chamber comprises an isolation valve and selecting a range of isolation valve closure times as a function of a targeted depth of investigation value within the underground formation surrounding the well.
 8. A method according to claim 7, wherein the targeted depth of investigation is determined using a measured real-time bottom hole pressure data.
 9. An apparatus usable in a well comprising: a tubular member including a chamber; an isolation valve disposed in the tubular member to control fluid flow from the well into the chamber in connection with a well testing operation; and means determine the optimal time to close the isolation valve and isolating the chamber from the well.
 10. Apparatus according to claim 9, wherein the tubular member comprises a coiled tubing.
 11. Apparatus according to claim 9, wherein the upper end of the chamber is directly connected to a production facility. 